Acid gas removal from various gas streams, and especially removal of carbon dioxide from natural gas streams has become an increasingly important process as the acid gas content of various gas sources is relatively high, or increases over time. For example, there are relatively large natural gas resources (e.g., Alaska, Continental North America, Norway, Southeast Asia, or Gulf of Mexico) that contain high concentrations of carbon dioxide ranging from 20% to 75%. Moreover, where enhanced oil recovery (EOR) is employed, the carbon dioxide concentration in natural gas will increase over time to significant concentrations that will typically require gas processing to remove at least part of the carbon dioxide.
Currently more than half of the natural gas produced in the U.S. is treated to meet pipeline specification with minimal processing, and such processing frequently includes glycol dehydration and hydrocarbon removal. Untreated gas with high carbon dioxide content is usually left in the ground, mostly due to economical and/or technical considerations.
Among other difficulties, removal of impurities (primarily water, hydrogen sulfide, and/or carbon dioxide) is generally required to transport the treated natural gas through pipelines, which significantly increases production costs. Furthermore, many known acid gas removal processes also remove a portion of the methane and other hydrocarbons. (Losses of less than about 2% of hydrocarbons are normally acceptable, losses of 5-10% may be acceptable if the value of the product gas is high or offset by other advantages, while losses above 10% are normally unacceptable). Still further, the removed carbon dioxide must typically be recompressed back to the high pressure formation to reduce its environmental impact and for enhanced oil recovery, which is energy intensive and therefore economically unattractive.
To overcome at least some of the disadvantages associated with acid gas removal, numerous processes were developed and may be categorized into various categories, wherein the choice of the appropriate gas treatment will predominantly depend on the gas composition, the size and location of the plant, and other variables.
For example, in one category one or more membranes are used to physically separate the acid gas from a gaseous feed stream, wherein a typical membrane system includes a pre-treatment skid and a series of membrane modules. Membrane systems are often highly adaptable to accommodate treatment of various gas volumes and product-gas specifications. Furthermore, membrane systems are relatively compact and are generally free of moving parts, therefore rendering membrane systems an especially viable option for offshore gas treatment. However, all or almost all single stage membrane separators are relatively non-selective and therefore produce a carbon dioxide permeate stream with a relatively high methane and hydrocarbon content (which is either vented, incinerated or used as a low BTU fuel gas). Consequently, the high methane and hydrocarbon losses tend to render the use of this process undesirable and uneconomical. To reduce such losses, multiple stages of membrane separators with inter-stage recompression may be used. However, such systems tend to be energy intensive and costly.
In another category, a chemical solvent is employed that reacts with the acid gas to form a (typically non-covalent) complex with the acid gas. In processes involving a chemical reaction between the acid gas and the solvent, the crude gases are typically scrubbed with an alkaline salt solution of a weak inorganic acid (e.g., U.S. Pat. No. 3,563,695 to Benson), or with an alkaline solution of organic acids or bases (e.g., U.S. Pat. No. 2,177,068 to Hutchinson). One particular advantage of a chemical solvent system is that such systems typically absorb methane to a relatively low degree. Furthermore, chemical solvent systems often produce a product gas with a very low acid gas content.
However, while use of chemical solvent systems may be advantageous in at least some respects (see above), substantial difficulties are frequently inherent. For example, once the chemical solvent is spent, the acid gas is flashed off and the solvent is regenerated using heat, which may add substantial cost to the acid gas removal. Furthermore, the mechanical equipment in a gas treatment plant using a chemical solvent is often prone to failure from either corrosion or foaming problems. Still further, chemical solvent systems typically include columns, heaters, air coolers, pumps, etc., all of which require frequent quality checks and maintenance, making operational reliability probably the weakest feature of such systems. Yet another disadvantage of chemical solvent systems is that the product gas and carbon dioxide streams must typically be further dried to meet pipeline specifications. Moreover, the quantity of chemical solvent required to absorb increasing amounts of acid gases generally increases proportionally with acid gas quantity, thus making the use of chemical solvents problematic where the acid gas content increases over time in the feed gas.
In a still further category, a physical solvent is employed for removal of acid gas from a feed gas, which is particularly advantageous for treating gas with a high acid gas partial pressure as the potential treating capacity of the physical solvent increases with the acid gas partial pressure (Henry's law). Using physical solvents, absorption of a particular acid gas predominantly depends upon the particular solvent employed, and is further dependent on pressure and temperature of the solvent. For example, methanol may be employed as a low-boiling organic physical solvent, as exemplified in U.S. Pat. No. 2,863,527 to Herbert et al. However, the refrigerant cooling requirement to maintain the solvent at cryogenic temperatures is relatively high, and the process often exhibits greater than desired methane and ethane absorption, thereby necessitating large energy input for recompression and recovery.
Alternatively, physical solvents may be operated at ambient or slightly below ambient temperatures, including propylene carbonates as described in U.S. Pat. No. 2,926,751 to Kohl et al., and those using N-methylpyrrolidone or glycol ethers as described in U.S. Pat. No. 3,505,784 to Hochgesand et al. In further known methods, physical solvents may also include ethers of polyglycols, and specifically dimethoxytetraethylene glycol as shown in U.S. Pat. No. 2,649,166 to Porter et al., or N-substituted morpholine as described in U.S. Pat. No. 3,773,896 to Preusser et al. While use of physical solvents avoids at least some of the problems associated with chemical solvents or membranes, various new difficulties arise. Among other things, most known solvent processes lack an efficient heat exchange integration configuration, and often require significant refrigeration and/or high solvent circulation, and sometimes require heat for solvent regeneration. In most or almost most of the known physical solvent processes, co-absorption of methane and hydrocarbons can be relatively high due to the high solvent circulation.
Furthermore, where relatively low carbon dioxide content in the product gas is required, various physical solvent processes require steam or external heat for solvent regeneration. A typical physical solvent process is exemplified in Prior Art FIG. 1, which is conceptually relatively simple and employs use of a cold lean solvent to remove carbon dioxide from the feed gas. The solvent is regenerated by successive flashing to lower pressures and the flashed solvent is then pumped to the absorber, wherein the solvent is cooled using external refrigeration (either in the rich solvent or the lean solvent circuit). In most instances, a steam or fuel fired heater is required for solvent regeneration.
In such processes, as carbon dioxide is absorbed by the solvent, the heat of solution of carbon dioxide increases the solvent temperature resulting in a top-to-bottom increasing temperature profile across the absorber. Consequently, one limitation of physical absorption lies in the relatively high absorber bottom temperature, which limits carbon dioxide absorption capacity of the solvent. To overcome the problems associated with limited absorption capacity, the solvent circulation rate may be increased. However, increase in solvent circulation significantly increases refrigeration costs and energy consumption for pumping the solvent. Worse yet, high solvent circulation of known solvent processes will lead to increased loss of methane and hydrocarbons (due to co-absorption). Yet another undesirable aspect of known physical solvent processes is problematic heat and mass transfer due to the cold lean solvent temperature entering the top of the absorber: While a relatively cold lean solvent is required to reduce solvent circulation in known processes, further reduction of the lean solvent temperature becomes undesirable as the solvent's surface tension and viscosity increase, eventually leading to hydraulic problems.
Moreover, in all or almost all of the known acid gas removal processes using solvents the acid gas is removed in the regenerator at low or substantially atmospheric pressure. Consequently, and especially where the carbon dioxide is later used for EOR, the isolated carbon dioxide must be compressed to substantial pressures, which further increases process costs. Thus, although various configurations and methods are known to remove acid gases from a feed gas, all or almost all of them suffer from one or more disadvantages. Therefore, there is still a need to provide methods and configurations for improved acid gas removal.